Abstract:

The present invention is a method and apparatus for the enhanced recovery
of petroleum fluids from the subsurface by in situ combustion of the
hydrocarbon deposit, from injection of an oxygen rich gas and drawing off
a flue gas to control the rate and propagation of the combustion front to
be predominantly horizontal and propagating vertically downwards guided
by the vertical highly permeable hydraulic fractures. Multiple propped
vertical hydraulic fractures are constructed from the well bore into the
oil sand formation and filled with a highly permeable proppant containing
hydrodesulfurization and thermal cracking catalysts. The oxygen rich gas
is injected via the well bore into the top of the propped fractures, the
in situ hydrocarbons are ignited by a downhole burner, and the generated
flue gas extracted from the bottom of the propped fractures through the
well bore and mobile oil gravity drains through the propped fractures to
the bottom of the well bore and pumped to the surface. The combustion
front is predominantly horizontal, providing good vertical and lateral
sweep, due to the flue gas exhaust control provided by the highly
permeable propped fractures.

Claims:

1-26. (canceled)

27. A method for the in situ recovery of hydrocarbons from a hydrocarbon
containing formation, comprising:a. drilling a bore hole in the formation
to a predetermined depth to define a well bore with a casing;b.
installing one or more vertical proppant and diluent filled hydraulic
fractures from the bore hole to create a process zone within the
formation by injecting a fracture fluid into the casing;c. placing a
downhole electric pump, a downhole packer, piping, and at least two drop
tubes inside the casing, wherein one drop tube is used for flue gas
extraction and another drop tube is used for injection of the oxygen rich
gas;d. injecting an oxygen rich gas into a section of the bore hole
connected to the hydraulic fractures;e. igniting the hydrocarbon
deposit;f. exhausting a combustion gas from the formation; andg.
recovering a hydrocarbon from the formation through the piping inside the
casing.

28. The method of claim 27, further including the step of installing a top
and bottom screen in the casing, wherein a hydraulic connection from the
casing well bore to the propped fractures and the oil sand formation is
established.

29. The method of claim 27, wherein the oxygen rich gas is injected at the
top of the hydraulic fractures through the drop tube, through the top
screen, and into the propped fractures.

30. The method of claim 27, wherein the hydrocarbon deposit is ignited by
a downhole burner placed inside the casing.

31. The method of claim 27, further including the step of pooling the
hydrocarbon at the bottom of the hydraulic fracture, wherein the
hydrocarbon enters into the well bore through the lower screen and
accumulates at a location adjacent to the downhole electric pump.

32. The method of claim 27, wherein the produced hydrocarbon mixture flows
through a hot spent combusted zone.

33. The method of claim 27, wherein flue gas is extracted by the drop
tube.

34. The method of claim 29, wherein the injected gas is air.

35. The method of claim 29, wherein the injected gas is a mixture of
oxygen and carbon dioxide.

36. The method of claim 27, wherein the combusted gas is separated into
carbon dioxide and a fuel gas.

37. The method of claim 35, wherein the carbon dioxide produced is
re-injected into the formation.

38. The method of claim 27, wherein the hydraulic fractures are filled
with proppants of differing permeability.

39. The method of claim 27, wherein the proppant of the hydraulic
fractures contains a catalyst or a mixture of catalysts.

40. The method of claim 39, wherein the catalyst is one of a group of
hydrodesulfurization catalysts or thermal cracking catalysts or a mixture
thereof.

41. The method of claim 27, wherein a catalyst or mixture of catalysts are
placed in a canister in the well bore through which the produced
hydrocarbons flow.

42. The method of claim 41, wherein the catalyst is one of a group of
hydrodesulfurization catalysts or thermal cracking catalysts or a mixture
thereof.

43. The method of claim 27, wherein the pressure in the majority of the
part of the process zone is at ambient reservoir pressure.

44. The method of claim 27, wherein at least two vertical fractures are
installed from the bore hole at approximately orthogonal directions.

45. The method of claim 27, wherein at least three vertical fractures are
installed from the bore hole.

46. The method of claim 27, wherein at least four vertical fractures are
installed from the bore hole.

47. A well in a formation of unconsolidated and weakly cemented sediments,
comprising:a. a bore hole in the formation to a predetermined depth;b. an
injection casing grouted in the bore hole at the predetermined depth,
wherein the injection casing comprises winged initiation sections;c. a
bottom screen and a top screen in said injection casing, whereby the bore
hole is capable of hydraulic connection to the propped fractures and the
oil sand formation;d. an electric downhole pump inside of said casing;e.
a cable connected to said electric downhole pump;f. a downhole packer
above said bottom screen inside said casing;g. a first drop tube for flue
gas extraction inside said casing, whereby flue gas can be extracted from
said bore hole;h. a second drop tube for gas injection inside said
casing, whereby oxygen enriched gas can be injected into said bore
hole;i. piping inside said casing, whereby hydrocarbons can be produced
from said oil sand formation.j. a source for delivering fracture fluid
into the injection casing with sufficient fracturing pressure to dilate
the injection casing and the formation and initiate a vertical hydraulic
fracture, having a fracture tip, at an azimuth orthogonal to the
direction of dilation to create a process zone within the formation, for
controlling the propagation rate of a wing of the hydraulic fracture;k. a
source of oxygen rich gas connected to the casing and the propped
hydraulic fractures; andl. an ignition source for igniting the
hydrocarbon deposit in the presence of the oxygen rich gas, wherein a
resulting combustion gas from the formation is exhausted through the
casing and petroleum hydrocarbons from the formation are recovered
through the casing.

48. The well of claim 47, wherein the second drop tube is fluidly
connected to the top screen.

49. The well of claim 47, wherein the piping is fluidly connected to the
bottom screen.

50. The well of claim 47, further comprising an oil pool at the bottom of
the hydraulic fracture fluidly connected to the bottom screen and the
piping and adjacent the downhole electric pump.

51. The well of claim 47, wherein the injection casing comprises eight
symmetrical fracture initiation sections to install two hydraulic
fractures on different azimuth planes.

52. A method for the in situ recovery of hydrocarbons from a hydrocarbon
containing formation, comprising:a. drilling a bore hole in the formation
to a predetermined depth to define a well bore with a casing;b.
installing one or more vertical proppant and diluent filled hydraulic
fractures from the bore hole to create a process zone within the
formation by injecting a fracture fluid into the casing;c. washing the
fracture fluid from the casing;d. placing a downhole electric pump, a
downhole packer, piping, and at least two drop tubes inside the casing,
wherein one drop tube is used for flue gas extraction and another drop
tube is used for injection of the oxygen rich gas;e. injecting an oxygen
rich gas at ambient reservoir pressure through a drop tube inside the
casing and through a top screen in the casing fluidly connected to the
hydraulic fractures;f. igniting the injected gas with a downhole
burner;g. igniting the hydrocarbons in the formation in the vicinity of
the injected gas to create a combustion front;h. draining the heated oil
by gravity into the bottom of the hydraulic fracture and through a bottom
screen in the casing fluidly connected to the hydraulic fracture;i.
controlling the propagation rate and growth of the combustion front by
varying the extraction rate of the flue gas; andj. recovering a
hydrocarbon from the formation through the bottom screen through tubing
inside the casing fluidly connected to the bottom screen.

[0002]The present invention generally relates to the enhanced recovery of
petroleum fluids from the subsurface by the injection of an oxygen
enriched gas into the oil sand formation for in situ combustion of the
viscous heavy oil and bitumen in situ, and more particularly to a method
and apparatus to extract a particular fraction of the in situ hydrocarbon
reserve by controlling the access to the in situ bitumen, the rate and
growth of the combustion front, the flue gas composition, the flow of
produced hydrocarbons through a hot zone containing a catalyst for
promoting in situ hydrodesulfurization and thermal cracking, the
operating reservoir pressures of the in situ process, thus resulting in
increased production and quality of the produced petroleum fluids from
the subsurface formation as well as limiting water inflow into the
process zone.

BACKGROUND OF THE INVENTION

[0003]Heavy oil and bitumen oil sands are abundant in reservoirs in many
parts of the world such as those in Alberta, Canada, Utah and California
in the United States, the Orinoco Belt of Venezuela, Indonesia, China,
and Russia. The hydrocarbon reserves of the oil sand deposit is extremely
large in the trillions of barrels, with recoverable reserves estimated by
current technology in the 300 billion barrels for Alberta, Canada and a
similar recoverable reserve for Venezuela. These vast heavy oil (defined
as the liquid petroleum resource of less than 20° API gravity)
deposits are found largely in unconsolidated sandstones, being high
porosity permeable cohensionless sands with minimal grain to grain
cementation. The hydrocarbons are extracted from the oils sands either by
mining or in situ methods.

[0004]The heavy oil and bitumen in the oil sand deposits have high
viscosity at reservoir temperatures and pressures. While some
distinctions have arisen between tar and oil sands and between bitumen
and heavy oil, these terms will be used interchangeably herein. The oil
sand deposits in Alberta, Canada extend over many square miles and vary
in thickness up to hundreds of feet thick. Although some of these
deposits lie close to the surface and are suitable for surface mining,
the majority of the deposits are at depth ranging from a shallow depth of
150 feet down to several thousands of feet below ground surface. The oil
sands located at these depths constitute some of the world's largest
presently known petroleum deposits. The oil sands contain a viscous
hydrocarbon material, commonly referred to as bitumen, in an amount that
ranges up to 15% by weight. Bitumen is effectively immobile at typical
reservoir temperatures. For example at 15° C., bitumen has a
viscosity of ˜1,000,000 centipoise. However at elevated
temperatures the bitumen viscosity changes considerably to be ˜350
centipoise at 100° C. down to ˜10 centipoise at 180°
C. The oil sand deposits have an inherently high permeability ranging
from ˜1 to 10 Darcy, thus upon heating, the heavy oil becomes
mobile and can easily drain from the deposit.

[0005]In situ methods of hydrocarbon extraction from the oil sands consist
of cold production, in which the less viscous petroleum fluids are
extracted from vertical and horizontal wells with sand exclusion screens,
CHOPS (cold heavy oil production system) cold production with sand
extraction from vertical and horizontal wells with large diameter
perforations thus encouraging sand to flow into the well bore, CSS
(cyclic steam stimulation) a huff and puff cyclic steam injection system
with gravity drainage of heated petroleum fluids using vertical and
horizontal wells, steamflood using injector wells for steam injection and
producer wells on 5 and 9 point layout for vertical wells and
combinations of vertical and horizontal wells, SAGD (steam assisted
gravity drainage) steam injection and gravity production of heated
hydrocarbons using two horizontal wells, VAPEX (vapor assisted petroleum
extraction) solvent vapor injection and gravity production of diluted
hydrocarbons using horizontal wells, and the THAI (toe heel air
injection), a vertical injector well located near the base of a
horizontal producer well for an in situ combustion process, and
combinations of these methods.

[0006]Cyclic steam stimulation and steamflood hydrocarbon enhanced
recovery methods have been utilized worldwide, beginning in 1956 with the
discovery of CSS, huff and puff or steam-soak in Mene Grande field in
Venezuela and for steamflood in the early 1960s in the Kern River field
in California. These steam assisted hydrocarbon recovery methods
including a combination of steam and solvent are described, see U.S. Pat.
No. 3,739,852 to Woods et al, U.S. Pat. No. 4,280,559 to Best, U.S. Pat.
No. 4,519,454 to McMillen, U.S. Pat. No. 4,697,642 to Vogel, and U.S.
Pat. No. 6,708,759 to Leaute et al. The CSS process raises the steam
injection pressure above the formation fracturing pressure to create
fractures within the formation and enhance the surface area access of the
steam to the bitumen. Successive steam injection cycles reenter earlier
created fractures and thus the process becomes less efficient over time.
CSS is generally practiced in vertical wells, but systems are operational
in horizontal wells, but have complications due to localized fracturing
and steam entry and the lack of steam flow control along the long length
of the horizontal well bore.

[0007]Descriptions of the SAGD process and modifications are described,
see U.S. Pat. No. 4,344,485 to Butler, and U.S. Pat. No. 5,215,146 to
Sanchez and thermal extraction methods in U.S. Pat. No. 4,085,803 to
Butler, U.S. Pat. No. 4,099,570 to Vandergrift, and U.S. Pat. No.
4,116,275 to Butler et al. The SAGD process consists of two horizontal
wells at the bottom of the hydrocarbon formation, with the injector well
located approximately 10-15 feet vertically above the producer well. The
steam injection pressures exceed the formation fracturing pressure in
order to establish connection between the two wells and develop a steam
chamber in the oil sand formation. Similar to CSS, the SAGD method has
complications, albeit less severe than CSS, due to the lack of steam flow
control along the long section of the horizontal well and the difficulty
of controlling the growth of the steam chamber.

[0008]A thermal steam extraction process referred to a HASDrive (heated
annulus steam drive) and modifications thereof are described to heat and
hydrogenate the heavy oils in situ in the presence of a metal catalyst,
see U.S. Pat. No. 3,994,340 to Anderson et al, U.S. Pat. No. 4,696,345 to
Hsueh, U.S. Pat. No. 4,706,751 to Gondouin, U.S. Pat. No. 5,054,551 to
Duerksen, and U.S. Pat. No. 5,145,003 to Duerksen. It is disclosed that
at elevated temperature and pressure the injection of hydrogen or a
combination of hydrogen and carbon monoxide to the heavy oil in situ in
the presence of a metal catalyst will hydrogenate and thermal crack at
least a portion of the petroleum in the formation.

[0009]Thermal recovery processes using steam require large amounts of
energy to produce the steam, using either natural gas or heavy fractions
of produced synthetic crude. Burning these fuels generates significant
quantities of greenhouse gases, such as carbon dioxide. Also, the steam
process uses considerable quantities of water, which even though may be
reprocessed, involves recycling costs and energy use. Therefore a less
energy intensive oil recovery process is desirable.

[0010]Solvents applied to the bitumen soften the bitumen and reduce its
viscosity and provide a non-thermal mechanism to improve the bitumen
mobility. Hydrocarbon solvents consist of vaporized light hydrocarbons
such as ethane, propane, or butane or liquid solvents such as pipeline
diluents, natural condensate streams, or fractions of synthetic crudes.
The diluent can be added to steam and flashed to a vapor state or be
maintained as a liquid at elevated temperature and pressure, depending on
the particular diluent composition. While in contact with the bitumen,
the saturated solvent vapor dissolves into the bitumen. This diffusion
process is due to the partial pressure difference in the saturated
solvent vapor and the bitumen. As a result of the diffusion of the
solvent into the bitumen, the oil in the bitumen becomes diluted and
mobile and will flow under gravity. The resultant mobile oil may be
deasphalted by the condensed solvent, leaving the heavy asphaltenes
behind within the oil sand pore space with little loss of inherent fluid
mobility in the oil sands due to the small weight percent (5-15%) of the
asphaltene fraction to the original oil in place. Deasphalting the oil
from the oil sands produces a high grade quality product by
3°-5° API gravity. If the reservoir temperature is elevated
the diffusion rate of the solvent into the bitumen is raised considerably
being two orders of magnitude greater at 100° C. compared to
ambient reservoir temperatures of ˜15° C.

[0011]Solvent assisted recovery of hydrocarbons in continuous and cyclic
modes are described including the VAPEX process and combinations of steam
and solvent plus heat, see U.S. Pat. No. 4,450,913 to Allen et al, U.S.
Pat. No. 4,513,819 to Islip et al, U.S. Pat. No. 5,407,009 to Butler et
al, U.S. Pat. No. 5,607,016 to Butler, U.S. Pat. No. 5,899,274 to
Frauenfeld et al, U.S. Pat. No. 6,318,464 to Mokrys, U.S. Pat. No.
6,769,486 to Lim et al, and U.S. Pat. No. 6,883,607 to Nenniger et al.
The VAPEX process generally consists of two horizontal wells in a similar
configuration to SAGD; however, there are variations to this including
spaced horizontal wells and a combination of horizontal and vertical
wells. The startup phase for the VAPEX process can be lengthy and take
many months to develop a controlled connection between the two wells and
avoid premature short circuiting between the injector and producer. The
VAPEX process with horizontal wells has similar issues to CSS and SAGD in
horizontal wells, due to the lack of solvent flow control along the long
horizontal well bore, which can lead to non-uniformity of the vapor
chamber development and growth along the horizontal well bore.

[0012]Direct heating and electrical heating methods for enhanced recovery
of hydrocarbons from oil sands have been disclosed in combination with
steam, hydrogen, catalysts, and/or solvent injection at temperatures to
ensure the petroleum fluids gravity drain from the formation and at
significantly higher temperatures (300° to 400° range and
above) to pyrolysis the oil sands. See U.S. Pat. No. 2,780,450 to
Ljungstrom, U.S. Pat. No. 4,597,441 to Ware et al, U.S. Pat. No.
4,926,941 to Glandt et al, U.S. Pat. No. 5,046,559 to Glandt, U.S. Pat.
No. 5,060,726 to Glandt et al, U.S. Pat. No. 5,297,626 to Vinegar et al,
U.S. Pat. No. 5,392,854 to Vinegar et al, and U.S. Pat. No. 6,722,431 to
Karanikas et al

[0013]In situ combustion processes have been disclosed. See U.S. Pat. No.
4, 454,916 to Shu, U.S. Pat. No. 4,474,237 to Shu, U.S. Pat. No.
4,566,536 to Holmes et al, U.S. Pat. No. 4,598,770 to Shu et al, U.S.
Pat. No. 4,625,800 to Venkatesan, U.S. Pat. No. 4,993,490 to Stephens et
al, U.S. Pat. No. 5,211,230 to Ostapovich et al, U.S. Pat. No. 5,273,111
to Brannan et al, U.S. Pat. No. 5,339,897 to Leaute, U.S. Pat. No.
5,413,224 to Laali, U.S. Pat. No. 5,626,191 to Greaves et al, U.S. Pat.
No. 5,824,214 to Paul et al, U.S. Pat. No. 5,871,637 to Brons, U.S. Pat.
No. 5,954,946 to Klazinga et al, and U.S. Pat. No. 6,412,557 to Ayasse et
al. Many of these disclosed methods involve in situ combustion of the in
situ hydrocarbon deposit with a combination of vertical and horizontal
wells. The process involves the injection of an oxygen rich injection
gas, igniting the in situ hydrocarbons, either by direct ignition from a
standard downhole burner, or from self ignition, and drawing the produced
flue gas off to create a gas pressure gradient to control the rate and
progress of the combustion front. The difficulties experienced by the
various disclosed methods are: 1) initiating connection of the injector,
the combustion zone, and producer to get the process started, 2) the
potential for a liquid and/or gravity block, i.e. mobile hydrocarbons can
not flow to the producer or combustion (flue) gases rise vertically
rather than flow to the producer, and 3) the difficulty of raising the
temperature of the produced hydrocarbons to initiate some form of
hydrodesulfurization and/or thermal cracking. Some of the disclosed
processes overcome some of these difficulties by heating a zone and thus
connecting the injector and producer prior to injection of the oxygen
rich gas injection and ignition of the hydrocarbon formation. Other
methods force the produced hydrocarbons to flow through a spent
previously combusted zone to raise the temperature to induce some form of
cracking process, while others propose placement of a catalyst in the
producer well to promote further cracking at the elevated temperatures.
The THAI (toe heel air injection) combustion process has been
demonstrated in laboratory tests for application to oil sands, involving
air injection in a vertical well with the producer being a horizontal
well at a deeper depth and the combustion front progressing horizontally
along the alignment of the producer and downwards towards the producer.

[0014]In situ processes involving downhole heaters are described in U.S.
Pat. No. 2,634,961 to Ljungstrom, U.S. Pat. No. 2,732,195 to Ljungstrom,
U.S. Pat. No. 2,780,450 to Ljungstrom. Electrical heaters are described
for heating viscous oils in the forms of downhole heaters and electrical
heating of tubing and/or casing, see U.S. Pat. No. 2,548,360 to Germain,
U.S. Pat. No. 4,716,960 to Eastlund et al, U.S. Pat. No. 5,060,287 to Van
Egmond, U.S. Pat. No. 5,065,818 to Van Egmond, U.S. Pat. No. 6,023,554 to
Vinegar and U.S. Pat. No. 6,360,819 to Vinegar. Flameless downhole
combustor heaters are described, see U.S. Pat. No. 5,255,742 to Mikus,
U.S. Pat. No. 5,404,952 to Vinegar et al, U.S. Pat. No. 5,862,858 to
Wellington et al, and U.S. Pat. No. 5,899,269 to Wellington et al.
Surface fired heaters or surface burners may be used to heat a heat
transferring fluid pumped downhole to heat the formation as described in
U.S. Pat. No. 6,056,057 to Vinegar et al and U.S. Pat. No. 6,079,499 to
Mikus et al.

[0015]The thermal and solvent methods of enhanced oil recovery from oil
sands, all suffer from a lack of surface area access to the in place
bitumen. Thus the reasons for raising steam pressures above the
fracturing pressure in CSS and during steam chamber development in SAGD,
are to increase surface area of the steam with the in place bitumen.
Similarly the VAPEX process is limited by the available surface area to
the in place bitumen, because the diffusion process at this contact
controls the rate of softening of the bitumen. Likewise during steam
chamber growth in the SAGD process the contact surface area with the in
place bitumen is virtually a constant, thus limiting the rate of heating
of the bitumen. Therefore, the methods, heat and solvent, or a
combination thereof, would greatly benefit from a substantial increase in
contact surface area with the in place bitumen. Hydraulic fracturing of
low permeable reservoirs has been used to increase the efficiency of such
processes and CSS methods involving fracturing are described in U.S. Pat.
No. 3,739,852 to Woods et al, U.S. Pat. No. 5,297,626 to Vinegar et al,
and U.S. Pat. No. 5,392,854 to Vinegar et al. Also during initiation of
the SAGD process, overpressurized conditions are usually imposed to
accelerated the steam chamber development, followed by a prolonged period
of underpressurized condition to reduce the steam to oil ratio.
Maintaining reservoir pressure during heating of the oil sands has the
significant benefit of minimizing water inflow to the heated zone and to
the well bore.

[0016]In situ combustion methods all suffer from poor connection between
the injected gas location, combustion zone, and producer especially at
initiation, and during propagation and growth of the combustion front if
barren or shale lenses are present or if the oil sands have intrinsically
low vertical permeability. The in situ combustion method would benefit
greatly from having good connection between the injected gas location,
combustion zone, and the producer both at the initiation configuration
and throughout the propagation and growth of the combustion front. Highly
permeable vertical propped hydraulic fractures extending radially from
the injector would greatly benefit the process by providing a connection
to control the rate and growth of the combustion front and thus guide the
combustion front radially between the propped fracture system.

[0017]Hydraulic fracturing of petroleum recovery wells enhances the
extraction of fluids from low permeable formations due to the high
permeability of the induced fracture and the size and extent of the
fracture. A single hydraulic fracture from a well bore results in
increased yield of extracted fluids from the formation. Hydraulic
fracturing of highly permeable unconsolidated formations has enabled
higher yield of extracted fluids from the formation and also reduced the
inflow of formation sediments into the well bore. Typically the well
casing is cemented into the bore hole, and the casing perforated with
shots of generally 0.5 inches in diameter over the depth interval to be
fractured. The formation is hydraulically fractured by injecting the
fracture fluid into the casing, through the perforations, and into the
formation. The hydraulic connectivity of the hydraulic fracture or
fractures formed in the formation may be poorly connected to the well
bore due to restrictions and damage due to the perforations. Creating a
hydraulic fracture in the formation that is well connected hydraulically
to the well bore will increase the yield from the well, result in less
inflow of formation sediments into the well bore, and result in greater
recovery of the petroleum reserves from the formation.

[0018]Turning now to the prior art, hydraulic fracturing of subsurface
earth formations to stimulate production of hydrocarbon fluids from
subterranean formations has been carried out in many parts of the world
for over fifty years. The earth is hydraulically fractured either through
perforations in a cased well bore or in an isolated section of an open
bore hole. The horizontal and vertical orientation of the hydraulic
fracture is controlled by the compressive stress regime in the earth and
the fabric of the formation. It is well known in the art of rock
mechanics that a fracture will occur in a plane perpendicular to the
direction of the minimum stress, see U.S. Pat. No. 4,271,696 to Wood. At
significant depth, one of the horizontal stresses is generally at a
minimum, resulting in a vertical fracture formed by the hydraulic
fracturing process. It is also well known in the art that the azimuth of
the vertical fracture is controlled by the orientation of the minimum
horizontal stress in consolidated sediments and brittle rocks.

[0019]At shallow depths, the horizontal stresses could be less or greater
than the vertical overburden stress. If the horizontal stresses are less
than the vertical overburden stress, then vertical fractures will be
produced; whereas if the horizontal stresses are greater than the
vertical overburden stress, then a horizontal fracture will be formed by
the hydraulic fracturing process.

[0020]Hydraulic fracturing generally consists of two types, propped and
unpropped fracturing. Unpropped fracturing consists of acid fracturing in
carbonate formations and water or low viscosity water slick fracturing
for enhanced gas production in tight formations. Propped fracturing of
low permeable rock formations enhances the formation permeability for
ease of extracting petroleum hydrocarbons from the formation. Propped
fracturing of high permeable formations is for sand control, i.e. to
reduce the inflow of sand into the well bore, by placing a highly
permeable propped fracture in the formation and pumping from the fracture
thus reducing the pressure gradients and fluid velocities due to draw
down of fluids from the well bore. Hydraulic fracturing involves the
literally breaking or fracturing the rock by injecting a specialized
fluid into the well bore passing through perforations in the casing to
the geological formation at pressures sufficient to initiate and/or
extend the fracture in the formation. The theory of hydraulic fracturing
utilizes linear elasticity and brittle failure theories to explain and
quantify the hydraulic fracturing process. Such theories and models are
highly developed and generally sufficient for the art of initiating and
propagating hydraulic fractures in brittle materials such as rock, but
are totally inadequate in the understanding and art of initiating and
propagating hydraulic fractures in ductile materials such as
unconsolidated sands and weakly cemented formations.

[0021]Hydraulic fracturing has evolved into a highly complex process with
specialized fluids, equipment and monitoring systems. The fluids used in
hydraulic fracturing vary depending on the application and can be water,
oil, or multi-phased based gels. Aqueous based fracturing fluids consist
of a polymeric gelling agent such as solvatable (or hydratable)
polysaccharide, e.g. galactomannan gums, glycomannan gums, and cellulose
derivatives. The purpose of the hydratable polysaccharides is to thicken
the aqueous solution and thus act as viscosifiers, i.e. increase the
viscosity by 100 times or more over the base aqueous solution. A
cross-linking agent can be added which further increases the viscosity of
the solution. The borate ion has been used extensively as a cross-linking
agent for hydrated guar gums and other galactomannans, see U.S. Pat. No.
3,059,909 to Wise. Other suitable cross-linking agents are chromium,
iron, aluminum, zirconium (see U.S. Pat. No. 3,301,723 to Chrisp), and
titanium (see U.S. Pat. No. 3,888,312 to Tiner et al). A breaker is added
to the solution to controllably degrade the viscous fracturing fluid.
Common breakers are enzymes and catalyzed oxidizer breaker systems, with
weak organic acids sometimes used.

[0022]Oil based fracturing fluids are generally based on a gel formed as a
reaction product of aluminum phosphate ester and a base, typically sodium
aluminate. The reaction of the ester and base creates a solution that
yields high viscosity in diesels or moderate to high API gravity
hydrocarbons. Gelled hydrocarbons are advantageous in water sensitive oil
producing formations to avoid formation damage that would otherwise be
caused by water based fracturing fluids.

[0023]The method of controlling the azimuth of a vertical hydraulic
fracture in formations of unconsolidated or weakly cemented soils and
sediments by slotting the well bore or installing a pre-slotted or
weakened casing at a predetermined azimuth has been disclosed. The method
disclosed that a vertical hydraulic fracture can be propagated at a
pre-determined azimuth in unconsolidated or weakly cemented sediments and
that multiple orientated vertical hydraulic fractures at differing
azimuths from a single well bore can be initiated and propagated for the
enhancement of petroleum fluid production from the formation. See U.S.
Pat. No. 6,216,783 to Hocking et al, U.S. Pat. No. 6,443,227 to Hocking
et al, U.S. Pat. No. 6,991,037 to Hocking, and Hocking U.S. patent
application Ser. Nos. 11/363,540, 11/277,308, 11/277,775, 11/277,815, and
11/277,789. The method disclosed that a vertical hydraulic fracture can
be propagated at a pre-determined azimuth in unconsolidated or weakly
cemented sediments and that multiple orientated vertical hydraulic
fractures at differing azimuths from a single well bore can be initiated
and propagated for the enhancement of petroleum fluid production from the
formation. It is now known that unconsolidated or weakly cemented
sediments behave substantially different from brittle rocks from which
most of the hydraulic fracturing experience is founded.

[0024]Accordingly, there is a need for a method and apparatus for
enhancing the extraction of hydrocarbons from oil sands by in situ
combustion, direct heating, steam, and/or solvent injection or a
combination thereof and controlling the subsurface environment, both
temperature and pressure, to optimize the hydrocarbon extraction in terms
of produced rate, efficiency, and produced product quality, as well as
limit water inflow into the process zone.

SUMMARY OF THE INVENTION

[0025]The present invention is a method and apparatus for the enhanced
recovery of petroleum fluids from the subsurface by in situ combustion of
the hydrocarbon deposit, by injecting an oxygen rich gas, and by drawing
off a flue gas to control the rate and progation of the combustion front
to be predominantly radially away from the well bore and downwards to the
bottom of the well bore, from which the produced flue gas and
hydrocarbons are extracted. Multiple propped hydraulic fractures are
constructed from the well bore into the oil sand formation and filled
with a highly permeable proppant. The oxygen rich gas is injected via the
well bore into the top of the propped fractures, the in situ hydrocarbons
are ignited by a downhole burner, and the generated flue gas are
extracted from the bottom of the propped fractures through the well bore.
A mobile oil zone forms in front of the combustion front, and the oil,
under the influence of gravity, drains through the propped fractures to
the bottom of the well bore and is pumped to the surface. The injection
gas is injected into the well bore and into the propped fractures at or
near the ambient reservoir pressure but substantially below the reservoir
fracturing pressure. The flue gas is extracted at a rate to control the
propagation and shape of the combustion front and the resultant oxygen
content of the flue gas. The predominantly horizontal combustion front
propagates vertically downwards contacting the oil sands and in situ
bitumen between the vertical faces of the propped fractures. The
combustion front is predominantly horizontal, providing good vertical
sweep and advances vertically downwards with good lateral sweep, due to
the flue gas exhaust control provided by the highly permeable propped
fractures. Basically the combustion front is guided by the radially
entending vertical hydraulic fractures. The flue gas is composed of
combustion gases consisting of carbon monoxide, carbon dioxide, sulfur
dioxide, and water vapor.

[0026]The combustion front generates significant heat, which diffuses into
the bitumen ahead of the combustion front and heats the bitumen
sufficient for mobile oil to flow under gravity. The bitumen softens and
flows by gravity through the oil sands and the propped fractures to the
well bore. The generated flue gases and produced hydrocarbons flow down
the propped fractures to the well bore heating the proppant in the
process. The vertical downward growth of the combustion front consumes
the in situ hydrocarbons between the hydraulic fractures as it propagates
downwards. Thus the proppant in the lower portions of the propped
fractures have been significantly heated by the passage of the combustion
gases and thus are at sufficiently high a temperature to induce thermal
cracking of the cooler produced hydrocarbons draining by gravity through
this hot zone to the well bore. A catalyst placed as the proppant in the
fractures or placed in a canister in the well bore will further promote
hydrodesulfurization and thermal cracking and thus upgrade in situ the
quality of the produced hydrocarbon product. Such catalysts are really
available as HDS (hydrodesulfurization) metal containing catalysts and
FCC (fluid catalytic cracking) rare earth aluminum silica catalysts.

[0027]The in situ produced hydrocarbon product and flue gas are extracted
from the bottom section of the well bore, with the rate of flue gas
extraction controlling the rate and growth of the combustion front and
the resultant oxygen content of the flue gas. The injected gas could be
air or an enriched oxygen injected gas to limit degrading influences that
air injection has on the resulting the mobilized oil's viscosity. The
process can operate close to ambient reservoir pressures, so that water
inflow into the process zone can be minimized. Catalysts for
hydrodesulfurization and thermal cracking are contained in the proppant
of the hydraulic fractures or within a canister in the well bore. The
proppant zone in the lower portions of the hydraulic fractures will be
raised to high temperatures as the combustion gases pass through this
zone. Therefore the produced hydrocarbons will flow through this hot zone
and thus the catalysts will promote upgrading of the mobile oil by
hydrodesulfurization and thermal cracking of some portions of the
produced hydrocarbon.

[0028]Although the present invention contemplates the formation of
fractures which generally extend laterally away from a vertical or near
vertical well penetrating an earth formation and in a generally vertical
plane, those skilled in the art will recognize that the invention may be
carried out in earth formations wherein the fractures and the well bores
can extend in directions other than vertical.

[0029]Therefore, the present invention provides a method and apparatus for
enhanced recovery of petroleum fluids from the subsurface by the
injection of an oxygen enriched gas in the oil sand formation for the in
situ combustion of the viscous heavy oil and bitumen in situ, and more
particularly to a method and apparatus to extract a particular fraction
of the in situ hydrocarbon reserve by controlling the access to the in
situ bitumen, by controlling the rate and growth of the combustion front,
by controlling the flue gas composition, by controlling the flow of
produced hydrocarbons through a hot zone containing a catalyst for
promoting in situ hydrodesulfurization and thermal cracking, and by
controlling the operating reservoir pressures of the in situ process,
thus resulting in increased production and quality of the produced
petroleum fluids from the subsurface formation as well as limiting water
inflow into the process zone.

[0030]Other objects, features and advantages of the present invention will
become apparent upon reviewing the following description of the preferred
embodiments of the invention, when taken in conjunction with the drawings
and the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0031]FIG. 1 is a horizontal cross-section view of a well casing having
dual fracture winged initiation sections prior to initiation of multiple
azimuth controlled vertical fractures.

[0032]FIG. 2 is a cross-sectional side elevation view of a well casing
having dual fracture winged initiation sections prior to initiation of
multiple azimuth controlled vertical fractures.

[0033]FIG. 3 is an isometric view of a well casing having dual propped
fractures with downhole injected oxygen enriched gas, combustion front,
and gravity flow of produced hydrocarbons.

[0034]FIG. 4 is a horizontal cross-section view of a well casing having
multiple fracture dual winged initiation sections after initiation of all
four controlled vertical fractures.

[0035]FIG. 5 is an isometric view of a well casing having four propped
fractures with downhole injected oxygen enriched gas, combustion front,
and gravity flow of produced hydrocarbons.

DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENT

[0036]Several embodiments of the present invention are described below and
illustrated in the accompanying drawings. The present invention is a
method and apparatus for the enhanced recovery of petroleum fluids from
the subsurface by in situ combustion of the hydrocarbon deposit, by
injecting an oxygen rich gas, and by drawing off a flue gas to control
the rate and progation of the predominantly horizontal combustion front
to be vertically downwards. Multiple propped hydraulic fractures are
constructed from the well bore into the oil sand formation and filled
with a highly permeable proppant. The oxygen rich gas is injected via the
well bore into the top of the propped fractures, the in situ hydrocarbons
are ignited by a downhole burner, the generated flue gas is extracted
from the bottom of the propped fractures through the well bore, and the
mobile oil drains by gravity through the propped fractures to the bottom
of the well bore and is pumped to the surface. The combustion front is
predominantly horizontal, providing good vertical sweep and advances
vertically downwards with good lateral sweep, due to the flue gas exhaust
control provided by the highly permeable propped vertical fractures.

[0037]Referring to the drawings, in which like numerals indicate like
elements, FIGS. 1 and 2 illustrate the initial setup of the method and
apparatus for forming an in situ combustion enhanced recovery system of
the oil sand deposit, for the extraction of in situ upgraded processed
hydrocarbon fluids. Conventional bore hole 5 is completed by wash rotary
or cable tool methods into the formation 8 to a predetermined depth 7
below the ground surface 6. Injection casing 1 is installed to the
predetermined depth 7, and the installation is completed by placement of
a grout 4 which completely fills the annular space between the outside
the injection casing 1 and the bore hole 5. Injection casing 1 consists
of four initiation sections 21, 22, 23, and 24 to produce two fractures,
one orientated along plane 2, 2' and one orientated along plane 3, 3'.
Injection casing 1 must be constructed from a material that can withstand
the pressures that the fracture fluid exerts upon the interior of the
injection casing 1 during the pressurization of the fracture fluid and
the elevated temperatures imposed by the combustion process. The grout 4
is a special purpose cement for high temperature that preserves the
spacing between the exterior of the injection casing 1 and the bore hole
5 throughout the fracturing procedure and in situ combustion process,
preferably being a non-shrink or low shrink cement based grout that can
withstand the imposed temperatures and differential strains.

[0038]The outer surface of the injection casing 1 should be roughened or
manufactured such that the grout 4 bonds to the injection casing 1 with a
minimum strength equal to the down hole pressure required to initiate the
controlled vertical fracture. The bond strength of the grout 4 to the
outside surface of the casing 1 prevents the pressurized fracture fluid
from short circuiting along the casing-to-grout interface up to the
ground surface 6.

[0039]Referring to FIGS. 1, 2, and 3, the injection casing 1 comprises two
fracture dual winged initiation sections 21, 22, 23, and 24 installed at
a predetermined depth 7 within the bore hole 5. The winged initiation
sections 21, 22, 23, and 24 can be constructed from the same material as
the injection casing 1. The position below ground surface of the winged
initiation sections 21, 22, 23, and 24 will depend on the required in
situ geometry of the induced hydraulic fractures and the reservoir
formation properties and recoverable reserves.

[0040]The hydraulic fractures will be initiated and propagated by an oil
based fracturing fluid consisting of a gel formed as a reaction product
of aluminum phosphate ester and a base, typically sodium aluminate. The
reaction of the ester and base creates a solution that yields high
viscosity in diesels or moderate to high API gravity hydrocarbons. Gelled
hydrocarbons are advantageous in water sensitive oil producing formations
to avoid formation damage, that would otherwise be caused by water based
fracturing fluids. Alternatively a water based fracturing fluid gel can
be used.

[0041]The pumping rate of the fracturing fluid and the viscosity of the
fracturing fluid needs to be controlled to initiate and propagate the
fracture in a controlled manner in weakly cemented sediments such as oil
sands. The dilation of the casing and grout imposes a dilation of the
formation that generates an unloading zone in the oil sand, and such
dilation of the formation reduces the pore pressure in the formation in
front of the fracturing tip. The variables of interest are v the velocity
of the fracturing fluid in the throat of the fracture, i.e. the fracture
propagation rate, w the width of the fracture at its throat, being the
casing dilation at fracture initiation, and μ the viscosity of the
fracturing fluid at the shear rate in the fracture throat. The Reynolds
number is Re=ρvw/μ. To ensure a repeatable single orientated
hydraulic fracture is formed, the formation needs to be dilated
orthogonal to the intended fracture plane, and the fracturing fluid
pumping rate needs to be limited so that the Re is less than 100 during
fracture initiation and less than 250 during fracture propagation. Also
if the fracturing fluid can flow into the dilatant zone in the formation
ahead of the fracture and negate the induce pore pressure from formation
dilation then the fracture will not propagate along the intended azimuth.
In order to ensure that the fracturing fluid does not negate the pore
pressure gradients in front of the fracture tip, its viscosity, at
fracturing shear rates within the fracture throat of ˜1-20
sec-1, needs to be greater than 100 centipoise.

[0042]The fracture fluid forms a highly permeable hydraulic fracture by
placing a proppant in the fracture to create a highly permeable fracture.
Such proppants are typically clean sand for large massive hydraulic
fracture installations or specialized manufactured particles (generally
resin coated sand or ceramic in composition) that are designed also to
limit flow back of the proppant from the fracture into the well bore. Due
to the high temperatures experienced by the proppant during the
combustion process, the proppant material will be specially selected to
be temperature compatible with the process and consist of clean strong
sands, ceramic beads, HDS and FCC catalysts, or a mixture thereof. The
fracture fluid-gel-proppant mixture is injected into the formation and
carries the proppant to the extremes of the fracture. Upon propagation of
the fracture to the required lateral extent 31 and vertical extent 32,
the predetermined fracture thickness may need to be increased by
utilizing the process of tip screen out or by re-fracturing the already
induced fractures. The tip screen out process involves modifying the
proppant loading and/or fracture fluid properties to achieve a proppant
bridge at the fracture tip. The fracture fluid is further injected after
tip screen out, but rather then extending the fracture laterally or
vertically, the injected fluid widens, i.e. thickens, and fills the
fracture from the fracture tip back to the well bore. Multi-stage
fracturing involves injecting a proppant to form a hydraulic fracture 30
as shown as proppant material 50 (FIG. 3). Prior to creation of the full
fracture extent, however, a different proppant material is injected into
the fracture over a reduced central section of the well bore 53 to create
an area of the hydraulic fracture 51 loaded with a different proppant
material. Similarly the multi-stage fracturing could consist of a third
stage by injecting a different proppant material as shown by 52. The
purpose of injecting differing proppant materials is to select proppants
of differing permeability. The differing permeability of the proppants
enhances the circulation of the oil recovery fluids (steam, solvent and
injected/combusted gases) into the formed fracture so that the oil
recovery fluids can be extended laterally a greater distance compared to
a hydraulic fracture filled with a uniform permeable proppant. That is
the proppant materials are selected so that the proppant material 50 has
the highest proppant permeability, with proppant material 51 has a lower
proppant permeability, and with proppant material 52 having the lowest
proppant permeability. Such selection of proppant permeability can
optimize the lateral extent of the oil recovery fluids flowing within the
hydraulic fractures and controlling the geometry and propagation rate of
the combustion front. The permeability of the proppant materials will
typically range from 1 to 100 Darcy for material in the fracture zone 50,
i.e. generally being at least 10 times greater than the bitumen formation
permeability. The proppant material in fracture zone 51 is selected to be
lower than the material in fracture zone 50 by at least a factor of 2,
and proppant material in fracture zone 52 close to the well bore casing 1
is selected to be in the milli-Darcy range thus limiting fluid flow in
the fracture zone 52.

[0043]Referring to FIG. 3 for the in situ combustion process of oil sands,
the casing 1 is washed clean of fracturing fluids and screens 25 and 26
are present in the casing as a bottom screen 25 and a top screen 26 for
hydraulic connection from the casing well bore 1 to the propped fractures
30 and the oil sand formation 8. A downhole electric pump 17 is placed
inside the casing, connected to a power and instrumentation cable 18,
with downhole packer 19, drop tube 16 for flue gas extraction, drop tube
29 for injection of oxygen enriched gas, and piping 9 for production of
the produced hydrocarbons to the surface. The oxygen enriched injection
gas is injected into the well bore at the top of the hydraulic fractures,
through the drop tube 29, through the screen 26, and into the propped
fractures 30 and oil sand formation 8, as shown by flow vectors 12. The
injection pressure is very close to reservoir ambient pressure. The in
situ hydrocarbons in the formation 8 in the vicinity of the injected gas
are ignited by a downhole burner. The resulting combustion front
generates significant heat, which softens the bitumen in front of the
combustion front 10 and forms a fluid mobile hydrocarbon zone 28 in front
of the combustion front 10. The oil in the mobile zone 28 drains by
gravity 11 down to the bottom of the hydraulic fracture creating an oil
pool 54 and enters as shown by flow vectors 15 into the well bore through
the lower screen 25 and accumulates at location 13 adjacent the pump 17.
The accumulated oil is pumped by the pump 17 as shown by arrows 14
through the tubing 9 to the surface. The flue gas flows down to the lower
screen 25 as shown by flow vectors 27 in the spent combusted zone and is
extracted by the drop tube 16. The extraction rate of the flue gas
controls the propagation rate and growth of the combustion front, and the
resultant oxygen content of the flue gas. The extraction rate of the flue
gas is balanced to maintain an approximately horizontal combustion front
with good vertical and lateral sweep, and resulting in low oxygen content
in the flue gas. The operating pressure of the process is selected to be
close to the ambient reservoir pressure to minimize water inflow into the
process zone. The highly permeable hydraulic fractures enable close
control of flue gas exhaust and thus minimize the pressure difference
between the injected and exhausted gases required to operate the process.
The contrast in proppant permeability of the propped hydraulic fracture
30, i.e. zones 50, 51 and 52, control the flow of injected and combusted
gases and therefore controls the shape of the combusted front moving
through the bitumen formation 8. A low permeable proppant 52 placed close
to the well bore casing 1 will limit the extent of combustion in this
zone and thus reduce the exposure of the well bore casing 1 to combustion
temperatures.

[0044]The combustion zone 10 initially grows radially from the well bore
casing 1, i.e. parallel to the propped fractures 30. The combustion front
becomes predominantly horizontal as it reaches the lateral extent 31 of
the hydraulic fractures 30 and then propagates vertically downwards
eventually reaching the vertical extent 32 of the propped fracture system
30. At that point, the combustion front propagates radially back towards
the well bore casing 1. At this time, the bitumen in the lateral 31 and
vertical 32 extent of the propped fractures 30 is completely mobilized or
spent by the combustion process. It is at this stage that the process may
be stopped to limit the impact of the high combustion temperatures
impacting the well bore and also the potential for the injected gas to
preferentially short circuit to the flue gas extraction location at the
bottom of the well bore rather than be consumed in the combustion
process. The optimum configuration of the process, i.e. its maximum
lateral reach, will depend on the height of the pay zone, the contrast in
permeability of the proppant materials, the horizontal and vertical
permeabilities of the pay zone, the extent of barren or shale lenses
within the pay zone, and the ratio of propped fracture permeability to
host oil sand permeability.

[0045]Another embodiment of the present invention is shown on FIGS. 4 and
5, consisting of an injection casing 38 inserted in a bore hole 39 and
grouted in place by a grout 40. The injection casing 38 consists of eight
symmetrical fracture initiation sections 41, 42, 43, 44, 45, 46, 47, and
48 to install a total of four hydraulic fractures on the different
azimuth planes 31, 31', 32, 32', 33, 33', 34, and 34'. The process
results in four hydraulic fractures installed from a single well bore at
different azimuths as shown on FIGS. 4 and 5. The casing 1 is washed
clean of fracturing fluids and screens 25 and 26 are present in the
casing as a bottom screen 25 and top screen 26 for hydraulic connection
of the casing well bore 1 to the propped fractures 30 and the oil sand
formation 8. A downhole electric pump 17 is placed inside the casing,
connected to a power and instrumentation cable 18, with downhole packer
19, drop tube 16 for flue gas extraction, drop tube 29 for injection of
oxygen enriched gas, and piping 9 for production of the produced
hydrocarbons to the surface. The oxygen enriched injection gas is
injected into the well bore at the top of the hydraulic fractures through
the drop tube 29, through the screen 26 and into the propped fractures 30
and oil sand formation 8, as shown by flow vectors 12. The injection is
at a pressure very close to reservoir ambient pressure. The in situ
hydrocarbons in the formation 8 in the vicinity of the injected gas 12
are ignited by a downhole burner. The resulting combustion front
generates significant heat, which soften the bitumen in front of the
front and forms a fluid mobile hydrocarbon zone 28 in front of the
combustion front. The oil in the mobile zone 28 drains by gravity 11 down
to the bottom of the hydraulic fracture forming a pool of oil 54 and the
oil enters as shown by flow vectors 15 into the well bore through the
lower screen 25 and accumulates at location 13 adjacent the pump 17. The
accumulated oil is pumped by the pump 17 as shown by arrows 14 through
the tubing 9 to the surface. The flue gas is extracted by the drop tube
16 and flows down to the lower screen 25 as shown by flow vectors 27. The
extraction rate of the flue gas controls the propagation rate and growth
of the combustion front and the oxygen content of the flue gas. The
extraction rate of the flue gas is balanced to maintain a predominantly
horizontal combustion front with good vertical and lateral sweep of the
bitumen formation 8, and to yield low oxygen content in the flue gas. The
operating pressure of the process is selected to be close to the ambient
reservoir pressure to minimize water inflow into the process zone. The
highly permeable hydraulic fractures enable close control of flue gas
exhaust and thus minimize the pressure difference between the injected
and exhausted gases required to operate the process. The contrast in
proppant permeability of the propped hydraulic fracture 30, i.e. zones
50, 51 and 52, control the flow of injected and combusted gases and
therefore controls the shape of the combusted front moving through the
bitumen formation 8.

[0046]Finally, it will be understood that the preferred embodiment has
been disclosed by way of example, and that other modifications may occur
to those skilled in the art without departing from the scope and spirit
of the appended claims.